Tools exist for acquiring representative samples of reservoir hydrocarbon, such as the Modular Dynamics Tester™ of Schlumberger. These systems comprise probes, packers, and/or other means for connecting the internal mechanism of the tool with the formation. These systems also comprise pumps to extract reservoir fluid, fluid analysis devices to evaluate physical properties of the fluid including the quantity of mud filtrate, and fluid storage vessels to retrieve the fluid to surface. When these components are operated, they permit the acquisition of a sample representative of reservoir fluid with minimal contamination of filtrate that has invaded the reservoir pores close to the bore-hole wall. These fluid sampling systems contain tubulars that interconnect the probe/packer through often tortuous routes and valves containing restrictions. Ultimately, when the fluid analyzer indicates the mud contamination is sufficiently low, a sample is retrieved into bottles. Fluid sampling systems equipped with probes have been used with success in conventional oil and gas reservoirs, while dual packer systems have been used, for example, in formations of low-permeability.
Pumps within the sampling tools can operate with pressure differences between the formation and internal mechanisms of the tool of up to 7.5 kpsi. When the internal tool tubulars are filled with fluid of viscosity on the order of 1 cP at flow-rates of the order of 10 cm3/s, the pressure drop that arises is negligible compared to 7.5 kpsi. In addition, conventional oil is typically located in consolidated formations, such that the formation neither collapses nor enters as solid granules into the sampling tool.
The density of a single phase fluid is one of the fundamental physical parameters required to describe fluid flow within the reservoir or borehole, as well as to determine both the properties of the surface facilities and the economic value of the fluid. Density is also required to provide the volume translation factor for cubic equations of state that are then often used for reservoir simulation. A measure of the single phase fluid density within the sampling tool provides a real-time in-situ determination of bore-hole fluid contamination, as well as economic value. Immiscible fluids are required, or a separator may be needed to provide the single phase fluid. Measurements with emulsions may be performed if the volume of each co-mingled phase is known before the density of the oil is extracted, and this can be achieved with, for example, coincidence gamma-ray attenuation measurements with a micro Curie source. For most applications, an expanded uncertainty in density of ±0.01 ρ is sufficient.